Tubing Installation Assembly

ABSTRACT

Liner hanger running tool assemblies that may function as a treating string after the liner is set are disclosed. Such assemblies may have a stomp tool that with variable positions so that the stomp tool may be positioned optimally for run-in and them may be moved to a second position that is more optimal during treatment operations. The stomp tool may also serve as a locating device during high pressure treatment to permit full insertion of the seal assembly without impacting the liner hanger assembly with the bottom of the running tool.

CROSS REFERENCE TO RELATED APPLICATIONS

This original non-provisional application claims the benefit of U.S. Provisional Patent Application Ser. No. 62/608,215 filed on Dec. 20, 2017 and entitled “Improved Tubing Installation Assembly” which is incorporated by reference herein.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The present disclosure relates to systems, such as liner hangers and running tools, for running a tubing string into a subterranean well and cementing the tubing string in the borehole. Such systems are typically designed so that, once the liner hanger is in place and fully actuated, the running tool is removed from the well and a treating string is run into the well to connect to the liner hanger. Treating operations, such as fracturing, can then occur through the treating string. Embodiments of the present disclosure may permit the running tool to function as a landed seal assembly, allowing treating operations to occur without tripping the running string out and a treating string back in.

Field

The use of liners and liner hangers is well known in the art. A tubing string may be run into a well and secured to previously installed casing once the tubing string reaches its desired position. Such tubing string may comprise a liner, a liner hanger at the top of the liner, and a running string connected to and above the liner hanger. Upon actuation of the liner hanger—such as applicants Sentinel™ or Sentinel Shield™ liner hangers—slips or other holding devices may be radially expanded to engage the casing. The holding devices grip the casing and secure the tubing string (e.g. the liner) at the desired location and hold the weight of the tubing string, which may exceed several hundred thousand pounds, so that the liner does not fall further down the well.

Liner hangers may also include a packer, such as a liner top packer. Such packer is in place to prevent fluid communication between the annulus surrounding the liner and the region of the wellbore above the liner hanger. In some liner hangers, the packer is set by mechanical force applied to the top of the liner hanger assembly, such as to the top of a polished bore receptacle (PBR) or other tubing. The mechanical force may be applied by a stomp sub having dogs or collet fingers configured to engage the upper end of the PBR or other tubing. One example stomp sub having collet fingers is described in U.S. patent application Ser. No. 15/247,897, the disclosure of which is hereby incorporated in its entirety by reference. The force applied to the end of the PBR or other tubing may longitudinally compress an elastomeric packer element between setting rings and/or thimbles. Such longitudinally compressed elastomeric element thereby radially expands against the casing to form a fluid seal between the liner hanger assembly and the inner casing wall. Other embodiment liner top packers may incorporate a metal to metal seal which is formed by swedging of the packer element. Hangers with such metal element are within the scope herein.

For cemented liner completions, the liner top packer is typically set after the cement has been placed. Once the tubing string is anchored in the casing by engagement of the slips or other holding devices, the running string may be disconnected from the liner hanger assembly. Cement may then be pumped down the running string, through the liner hanger and liner, and then pushed up from the lower end of the liner so that the cement surrounds the liner and fills the wellbore annulus from bottom to top (e.g. from the toe of the liner back up to the element of the liner top packer). The running tool may contain a cement bushing or packoff to prevent cement flowing out of the running tool from move up into and around the PBR or other tubing rather than down through the liner or liner hanger. The liner top packer may be set after the cement is run and before it cures, allowing cement to cure both above and below the packer element.

A wiper plug, wiper dart, wiper ball, combinations thereof, or similar devices may be used to push the cement through and out of the liner. Such device may latch into and seal against a latch assembly at the toe of the well which closes off the interior of the liner from the annulus and prevents cement from flowing back into the liner. After the wiper dart or other device passes into the liner hanger, and in at least some cases after the wiper dart/wiper plug latches into the toe of the liner, the running tool may then be moved for setting of the liner top packer.

Once the packer is set, the running string, and running tool assembly on which the liner was previously suspended, may be removed from the well. A treating string, such as a frac string, may then be introduced into the well and connected to the liner hanger assembly, such as by stabbing into the PBR or other tubing at the top of the liner top packer. The treating string may a landed seal assembly, with a sealing element that engages and creates a fluid seal against the inside of the PBR or other tubing, forcing the treating fluid down the liner and isolating the annulus between the casing and the treating string from the fluid and fluid pressure used in the treatment. The sealing element is positioned within the PBR or other tubing so that the piston force from the treatment's fluid pressure does not force the landed seal assembly out of the PBR or other tubing. The treating string may have a locating sub to verify the position of the treating string with respect to the PBR or other tubing. For example, the treating string may have a simply top sub which tags the upper end of the PBR or upper tubing or may have a latch that connects to the upper end of the PBR or other tubing. Such locating sub's position may be fixed, such as through a pup joint, relative to the sealing element so that the position of the sealing element in the PBR or other tubing can be known through engagement of the locating sub with PBR or other tubing's upper end.

The need for separate running strings and treating strings increases the time and cost of completing wells. Trip times for these strings run from several hours and into days which increases rig time and the risk of accidents, delays, or other problems. Cost is further increased because of the different tools used in the running string and treating string.

Embodiments of the present disclosure eliminate the need for a separate running string and treating string, thereby improving the cost and risk factors associated with completing wells. Components of the running string may be configured to perform similar functions associated with a treating string. For example, the cement bushing of the running string may double as the landed seal of the frac string. Also, the stomp sub may double as a locating sub. To facilitate these components performing both functions, the stomp sub may be slidingly connected to tubing, such as a mandrel, positioned between the stomp stub and seal element or seal sub. This allows the stomp sub to be positioned generally adjacent to the seal element during the run-in and cementing stages and spaced apart from the seal element during the treating stages.

When used with reference to the figures, unless otherwise specified, the terms “upwell,” “above,” “top,” “upper,” “downwell,” “below,” “bottom,” “lower,” and like terms are used relative to the direction of normal production and/or flow of fluids and or gas through the tool and wellbore. Thus, normal production results in migration through the wellbore and production string from the downwell to upwell direction without regard to whether the tubing string is disposed in a vertical wellbore, a horizontal wellbore, or some combination of both. Similarly, during the fracing process, fracing fluids and/or gasses move from the surface in the downwell direction to the portion of the tubing string within the formation.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 shows a cross sectional view of one embodiment assembly according to the present disclosure.

FIG. 2 shows one embodiment running tool according to the present disclosure as it may be run into a well.

FIG. 3 shows one embodiment top sub according to the present disclosure.

FIG. 4 shows one embodiment stomp sub according to the present disclosure.

FIG. 5 shows one embodiment seal sub according to the present disclosure.

FIG. 6 shows one embodiment running tool according to the present disclosure partially retracted from within the polished bore receptacle.

FIG. 7 shows one embodiment running tool according to the present disclosure in a treating state.

FIG. 8 shows one embodiment of a stomp sub engaged on an end of a polished bore receptacle and connected to a top sub.

FIG. 1 illustrates an embodiment assembly according to the present disclosure. Assembly 100 comprises running string 110, polished bore receptacle or PBR 120, running mandrel 130, crossovers 140 and 150, seal sub 400, running nut 500, liner top packer 600 and hanging element 700. Top sub 200 and stomp sub 300 may be located around the running mandrel 130 and top sub 200 may be located such that it is partially surrounding the running mandrel 130 and a portion of the running string 110. Liner, not shown, may be connected below the hanging element 700 and may create a continuous tubing path for fluid flow between the assembly 100 and the subterranean formation to be treated and/or produced. The liner may include a hydraulic port sub at the toe, which is closed when run in but may be opened by application of fluid pressure.

Running string 110, running mandrel 130, crossovers 140, 150 and seal sub 400 connect to liner top packer 600 and thereby to PBR 120 and hanging element 700 through a releasable connection of the running nut 500 to the top of the liner top packer 600. In some embodiments, the running nut is threadedly connected to the liner top packer, such as through threaded connection 510, though other types of connection are within the scope of the present disclosure.

Liner top packer 600 may comprise a packer mandrel 640, with one or more elastomeric elements 630, setting slips 620, cone 625, and adaptor 610 for transferring force to the setting slips therearound. One or more setting sheer pins 612 may fix adaptor 610 to packer mandrel 640. PBR 120 is connected to adaptor 610 which engages setting slips 620. Setting slips 620 may also have shear pins, not shown, fixing it to packer mandrel 640.

Hanging element 700 may be a tubing anchor such as is illustrated in FIG. 1, may be a liner hanger such as Applicant's Sentinel™ Liner hanger or Applicant's liner hanger as described in U.S. patent application Ser. No. 15/610,559 or other device that holds the liner and assembly in a desired location when actuated. The illustrated hanger 700 has a hanger mandrel 750 with a piston assembly 710, cones 720, 730 and slips 740 therearound. A passageway 712 permits fluid communication between the interior of the anchor into the piston assembly 710. In certain embodiments, the inner diameter of the running tool, PBR, liner hanger and liner will be coordinated, e.g. substantially the same, to facilitate the desired pumping of cement and/or treatment fluids.

In operation, assembly 100 and attached liner are run into a well on running string 110 until the hanging element 700 and packing element 600 are in a desired location. Running string 110, assembly 100 and the liner may form a closed fluid system in which pressure may be increased by pumps attached to the running string 110 at surface. Such an increase in pressure is communicated through passageway 712 to a piston in piston assembly 710, applying force into the cones 720, 730 and slips 740, forcing the slips 740 outward to engage the casing string in which the assembly 100 has been placed. Once set, slips 740 can bear the weight of the PBR 120, liner top packer 600, hanging element 700 and attached liner, allowing the running tool to be disengaged from the liner top packer 600, such as by rotating the running string 110 to unthread a threaded connection.

FIG. 2 illustrates the configuration of the running tool inside the PBR 120 while connected to the liner top packer 600, e.g. during run in of the assembly 100 and any attached liner. Running tool comprises running nut 500, seal sub 400, crossovers 140, 150, running mandrel 130, top sub 200 and stomp sub 300. It will be appreciated that, in the embodiment of FIG. 2, running nut 500, seal sub 400 and crossovers 140, 150 are connected to one another in sequence, with crossover 140 connected to running mandrel 130. In the run in position, stomp sub 300 is fixed to crossover 140 via stomp sub shear pin (350 in FIG. 4).

Mandrel gap 105 represents a length of plain tubing, in the running mandrel 130 and in the PBR 120, around or in which there are no other features relevant to the objects of the present disclosure. Such mandrel gap 105 may be of variable length depending on the stroke length desired for the running tool inside the PBR 120 or other factors. In some embodiments, the length of tubing corresponding to the mandrel gap 105 may be about 10 to about 12 feet, though the exact length may vary substantially. Similarly, running nut gap 505 represents a length (such as about 24 inches) of the running nut 500 and a corresponding portion of the PBR 120. Mandrel gap 105 and running nut gap 505 are included for illustration purposes only in order to decrease the length of certain figures, thereby assisting in the illustration of other portions of the running tool.

The top sub 200, stomp sub 300 and seal sub 400 may be generally tubular and are shown in more detail in FIGS. 3, 4 and 5, respectively. Top sub 200 comprises a body 210 and a ratchet ring 220 positioned in a slot of body 210. Body 210 may be fixed to the running string 110 and overlap with the upper end of running mandrel 130. Internal shoulder 112 may be part of top sub 200 or, as illustrated in FIG. 3, of the bottom of running string 110.

It will be appreciated that different embodiment top subs may be employed. It is not required that top sub be configured so that it fixes to the stomp sub and any configuration top sub that may apply downward force to the stomp sub, including, e.g., a tool joint or other shoulder of a pipe joint in the running string, may be used as top sub.

Stomp sub 300, which may be a dog sub as shown in FIG. 4, comprises a body 310, upper retainer 320, a plurality of dogs 330 with springs 332 arranged around circumference of dog sub, lower retainer 340, stomp sub shear pin 350, and rack 305. Bolts or screws 302 may be used to secure, or partially secure, retainers or other components to the body 310. Stomp sub 300 slidingly engages running mandrel 130 and may be secured to crossover 140 via stomp sub shear pin 350. Dogs 330 may be retained in their retracted position because of engagement of the dogs' 330 outer surface against the inner surface of PBR 120.

Seal sub 400 may comprise a body 405, seal stacks 410, 412, 414, 416, 418, 420, seal retainer 430, and seal stack ring 440. Seal stack ring 440 may be threadingly connected to body 405 or other component of seal sub such that turning seal stack ring 440 applies longitudinal force to seal retainer 430 and therethough to seal stacks 410, 412, 414, 416, 418, 420. Seal sub 400 may be configured such that the outer diameter of body 405 is smaller than the inner diameter of PBR 120 but permitting seals 410 through 420 to engage body 405 and inner diameter of PBR 120, creating a fluid tight seal therebetween. During cementing operations, seal sub may serve as a cement bushing.

Seal stacks 410 through 420 may be required to swab out of and into the PBR 120 multiple times. Further, at least one or more of seal stacks 410, 412, 414, 416, 418, 420 may be required to function after being removed from and then reinserted into PBR 120. In some embodiments, seal stacks 410 through 420 may be chevron seals, bonded seal assemblies or other sealing structures chosen to facilitate such movement and function, including sealing after removal and reinsertion. Further, while the illustrated embodiment contains six seal stacks, seal sub 400 may contain more or fewer such stacks.

After the hanging element is set, running tool may be released from the run in state. In some embodiments, such transition my begin by releasing the running nut 500 from the liner top packer 600. In the embodiment of FIGS. 1 and 2, this is done by unthreading the threaded connection 510. Such threaded connection may be a left-hand thread with all other threaded connections of the running string 110 and running tool being right-hand threads. This permits unthreading of the running nut 500 without backing off other threaded connections.

After the running nut is released, cementing of the liner may begin. Cement is pumped through the running string 110, assembly 100, and down the liner. Once the desired volume of cement has been pumped into the running string 110, a wiper plug may introduced into the running string 110. It will be appreciated that release of the running nut 500, and therefore the running tool, may create a length of open PBR between the running nut 500 and the upper end of the liner top packer 600. In some embodiments, the larger inner diameter of the PBR may permit a wiper plug to substantially exit the running tool before entering the packer and decentralize and to lodged between the running nut 500 and liner top packer 600. Therefore, it may be desirable to lower the running tool, and therefore the running nut to within 24 inches, and perhaps within 12 inches of the liner top packer 600 before the wiper plug exits the running nut 500. In such an arrangement, the wiper plug can remain substantially centralized in the running nut 500 to facilitate its entry into the liner top packer 600.

Following cementing, the running tool may be reciprocated within the PBR 120 and fluid circulated to help clear any cement from within the PBR 120 and or the running tool. The stomp sub 300 may be removed from the PBR 120 during or following this step. In some embodiments, reciprocation and removal of the running tool may facilitate clearing of debris from the PBR of other tubing in which the running tool is positioned. When stomp sub 300 is removed from the PBR 120, springs 332 force dogs 330 outward, causing dogs 330 to engage the upper end of PBR 120. Engagement of dogs 330 on the end of PBR 120 prevents movement of the running tool into the PBR 120. Downward force applied to the running string 110, and thereby to running mandrel 130 and crossovers 140, 150, causes the stomp sub shear pin 350 to break, releasing the stomp sub 300 and permitting the running mandrel 130 to slide within the stomp sub 300. Upper guide 320 and lower guide 340 may control or limit the movement of dogs 330 to assist in the dogs 330 proper positioning relative to the end of PBR 120.

FIG. 6 illustrates the running tool just prior to breaking stomp sub shear pins 350. Running string 110 and top sub 200 have been pulled upward away from the PBR 120 and the dogs 330 of stomp sub 300 are engaged against the upper edge of PBR 120. Running nut 500 has pulled away from the upper end of the liner top packer, as reflected by the continuation lines in PBR 120 at 107. After breaking the stomp sub shear pins 350, running mandrel 130 is slidable within the stomp sub 300, permitting reciprocation of the running tool. The running string 110 may then be moved down until the top sub 200 engages the stomp sub 300, as illustrated in FIGS. 7 and 8, placing the running tool in the treating state. Ratchet ring 220 engages rack 305 to connect the top sub 200 with stomp sub 300. Further, shoulder 112 may engage with a corresponding shoulder 307 on the body 310 of stomp sub 300 to facilitate the transfer of force from the running string 110 into the stomp tool 300. Once such engagement occurs, additional downward force on running string 110 is transferred through top sub 200, stomp sub 300 and to PBR 120 through dogs 330. It will be appreciated that, in this configuration, the stomp sub 300 is fixed along the running mandrel 130 distally from the crossover 140. Further, with stomp sub 300 engaged on PBR, running nut 500 has now moved to within about 24 inches, or other distance as may be desirable, of the upper end of the liner top packer 600.

Once the top sub 200 engages the stomp sub 300, the running tool may set the liner top packer 600. Force applied to the running string is transferred through the stomp sub 300 to the PBR 120 as described above, which is further transferred to the adaptor 610 and cone 625 of the liner top packer. The shear pins in cone 625 may be broken in response to such force and cone 625 moved towards the thimble 627 of the liner top packer 600. In certain embodiments it is desirable that the shear pins in cone 625 have greater strength than the stomp sub shear pins 350 so that stomp sub 300 can be released from running mandrel 130 without setting, or partially setting, liner top packer 600. Movement of cone 625 longitudinally compresses the elastomeric element 630, extruding the element 630 outward against the host casing and creating a fluid seal therebetween. After a desired pack off force is loaded into the element, packer slip shear pins 612 may release, allowing packer slips 620 to travel outward up the cone 625 to engage the casing and lock the cone 625 and element 630 in the set position.

Following setting of the liner top packer 600, the running tool may be removed from the PBR 120 so that fluid may be introduced in the annular space between the PBR 120 and the host casing. Following the introduction of such fluids, the running tool may be reinserted into the PBR 120, creating a fluid seal between the seal sub 400 and the inner wall of the PBR 120, creating a pressure isolated flowpath for subsequent treatment of the subterranean formation adjacent to the installed liner.

It will be appreciated that the spacing of the top sub 200 and the stomp sub 300 in the run in position must be configured to permit setting of all elements of the liner top packer 600. In the embodiments of FIGS. 1 and 2, this means permitting a stroke of PBR 120 sufficient to compress the element 630 and to set slips 620. In certain embodiments, this is accomplished by setting the gap between top sub 200 and stomp sub 300 between 12 and 24 inches less than the length required to remove the dogs 330 from the PBR. In other words, with reference to the configuration in FIG. 6, top sub 200 is between 12 and 24 inches closer to dog sub 300 than the running nut 500 is to the top of the liner top packer 600. This permits top sub 200 to apply downward force to stomp sub 300 and move PBR 120 without running nut 500 contacting the liner top packer 600. Further, in this position, seal sub 400 is positioned close to the bottom of the PBR, permitting substantially the full length of the PBR to be available during high pressure treating operations so that the piston effect from fluid pressure does not eject the seal assembly out of the PBR.

It will be appreciated that the running string will need to be selected based on both the tensile forces experienced during run in, the burst forces that may experienced during the treatment, and any chemicals the planned treatment may include. Such concerns are will known in the art and running strings meeting such parameters can be readily selected.

The present disclosure includes preferred or illustrative embodiments in which specific tools are described. For example, embodiment tools may incorporate one or more debris barriers or latches for engaging a PBR as are known in the art frac strings or other treating strings. Alternative embodiments of such tools can be used in carrying out the invention as claimed and such alternative embodiments are limited only by the claims themselves. Other aspects and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims. 

We claim:
 1. A downhole tool for installing a tubing string into a well or wellbore, the downhole tool having a run-in state and a treating state and comprising: a mandrel a top sub and a seal sub fixed to the mandrel; a stomp sub slidingly engaging the mandrel; wherein, the stomp sub is adjacent to the seal sub in the setting state and distal to the seal sub in the treating state; and the stomp sub is adjacent to the top sub in the treating state.
 2. The downhole tool of claim 1 further comprising a shear element fixing the stomp sub along the mandrel in the run-in state, wherein the stomp sub is released from the shear element in the treating state.
 3. The downhole tool of claim 2 wherein the shear element is at least one shear pin.
 4. The downhole tool of claim 1 further comprising a running nut releasably connected to the top of liner assembly, wherein the downhole tool is locked in the run-in state until the running nut is released from the liner assembly.
 5. The downhole tool of claim 1 wherein the running nut is releasably connected to a liner top packer.
 6. The downhole tool of claim 1 wherein the stomp sub is a dog sub comprising a plurality of radially expandable dogs.
 7. The downhole tool of claim 5 wherein the stomp sub is configured to prevent the running nut from contacting the liner top packer when the downhole tool is in the treating state.
 8. The downhole tool of claim 1 wherein the top sub is fixed to the stomp sub in the treating state.
 9. A landed seal assembly for sealing the interior of a polished bore receptacle connected above a liner top packer, the landed seal assembly having a run-in state and a treating state and comprising: a locater sub; a seal sub; and a top sub; a mandrel wherein, the top sub and the seal sub are fixed to the mandrel; the locater sub is inside the polished bore receptacle in the run-in state and above the polished bore receptacle in the set state; the mandrel extends between the top sub and the seal sub; the mandrel substantially extends between the top sub and the locater sub in the run-in position and between the locater sub and the seal sub in the treating position.
 10. The landed seal assembly of claim 9 wherein the locater sub is a stomp sub.
 11. The landed seal assembly of claim 9 where the locater sub is a dog sub with a plurality of expandable dogs arranged around the outer circumference of the dog sub, the plurality of dogs retracted in the run-in state and expanded in the treating state.
 12. The landed seal assembly of claim 9 wherein the locater sub slidingly engages the mandrel, is fixed to the mandrel in the run-in state and is fixed to the top sub in the treating state.
 13. The landed seal assembly of claim 9 further comprising a running nut connected to the liner top packer in the run in state.
 14. The landed seal assembly of claim 13 wherein the connection of the running nut to the liner top packer prevents transition of the landed seal assembly from the run in state to the treating state.
 15. The landed seal assembly of claim 9 wherein the seal sub comprises a plurality of chevron seals.
 16. A method for treating a subterranean formation penetrated by a well, the well comprising a casing string installed along an upper portion of the wellbore, the method comprising: running a tubing string into the wellbore, the tubing string having a continuous through bore and comprising: a liner, a liner hanger connected above the liner, a liner top packer, a tubing length connected above the liner top packer, and a running string having a running tool, the running tool comprising: a mandrel; a stomp sub positioned at least partially inside the tubing length and slidingly engaging the mandrel; a top sub; and a seal sub sealingly engaged with the tubing length; engaging the liner hanger with the casing; removing the stomp sub from inside the tubing length and engaging a portion of the stomp sub on an end of the tubing length; moving the top sub toward the stomp sub; moving the seal sub away from the stomp sub; setting the liner top packer with downward force from the running string applied to the stomp sub through the top sub; removing the running tool from the tubing length; reinserting the running tool into the tubing length and sealing the interior of the tubing length with the seal sub; treating the formation through the running tool, tubing length, liner top packer, liner hanger, and liner.
 17. The method of claim 16 wherein the running tool is connected to the liner top packer, the method comprising releasing the running tool from the liner top packer prior to removing the stomp sub from inside the tubing length.
 18. The method of claim 17 further comprising flowing cement through the running string and liner and placing the cement around the liner in the wellbore and into the casing adjacent to the liner top packer.
 19. The method of claim 18 further comprising running a wiper dart through the running tool, out of the running nut, and into the liner top packer.
 20. The method of claim 16 wherein the top sub and the seal sub are fixed along the length of the running tool and moving the seal sub away from the stomp sub happens contemporaneously with moving the top sub toward the stomp sub. 